Method of sweetening hydrocarbon gas from hydrogen sulfide

ABSTRACT

A two or particularly three-phase process, and corresponding apparatus, desulfurizes sour hydrocarbon gas, e.g., natural gas, generally better than known, using a fixed-bed, two-phase processes in terms of the amount of H2S scavenged and the breakthrough time of H2S. The three-phase process is effective in scavenging H2S at ambient temperature and pressure, using a copper salt catalyst impregnated on alumina or other generally inert support, which is regenerable.

BACKGROUND OF THE INVENTION Field of the Invention

The present application relates to methods and apparatuses fordesulfurizing petrochemical gases, particularly natural gas.

Description of the Related Art

Hydrogen sulfide (H₂S) is a colorless and highly corrosive and toxic gasthat exists in natural gas and also in other gases. The average H₂Sconcentration in natural gas is 4 ppmv at STP, which is considered thethreshold value for sweetening raw gas(es) to product gas(es). Theexistence of H₂S even at low concentrations leads to localized corrosionand also causes stress cracking. Therefore, H₂S gas should be scavengedbecause it causes damage to the pipelines, valves and surfaces ofprocess equipment.

Several technologies have been practiced industrially for sweetening(e.g., removing hydrogen sulfide) hydrocarbons and natural gas. Thesemethods mainly employ adsorption by amine solutions or adsorption oncarbonaceous or metal oxide adsorbents. These techniques suffer fromhigh processing costs, amine-based corrosion problems, limitedselectivity, and by-product generation. These problems, in part, havenecessitated development efforts for a solution. Thus, efforts towardsscavenging H₂S from natural gas and other sour gases have been made.

For example, U.S. Pat. No. 7,235,697 to Muller et al. (Muller) relatesto a process for preparing thiols, thioethers and disulfides by reactingolefins with hydrogen sulfide in the presence of water and carbondioxide. However, Muller does not describe particular metals, nordesulfurization. In another approach, U.S. Pat. No. 6,881,389 to Paulsenet al. (Paulsen) describes a system for removal of H₂S and/or CO₂ fromnatural gas via absorption and disassociation utilizing a sea watercontact system with a series of counter current scrubber stages, eachconfigured to remove via absorption/disassociation a portion of theimpurities, each stage having less pressure than the predecessor, eachstage redirecting the purified gas to the preceding stage, until thecontaminant level in the hydrocarbon gas stream has been reduced to anacceptable level. Paulsen's H₂S/CO₂ contaminants are sequestered in thesea water used in a scrubber. The sea water may be further processedand/or re-introduced into a deep body of water where the contaminantswill remain isolated for hundreds of years. Paulsen does not describe ametal catalyst, and particularly not copper.

U.S. Pat. No. 8,071,046 to Hassan et al. (Hassan) describes an apparatusand method for removing H₂S from a sour gas stream comprising H₂S, byoxidizing H₂S in a converter by contacting the sour gas stream with anaqueous catalytic solution, thereby producing a desulfurized gas streamand a liquid stream comprising reduced catalyst and elemental sulfur,introducing an oxidant and the liquid stream comprising reduced catalystand elemental sulfur into a high shear device and producing a dispersionwherein the mean bubble diameter of the oxidant gas in the dispersion isless than about 5 μm, introducing the dispersion into a vessel fromwhich a sulfur-containing slurry is removed and a regenerated catalyststream is removed, wherein the sulfur slurry comprises elemental sulfurand aqueous liquid, and recycling at least a portion of the regeneratedcatalyst stream to the converter. However, Hassan does not disclose acopper catalyst, but instead uses an Fe-based material. Hassan requiresa high shear device and a chelate in its homogeneous system.

U.S. Pat. No. 3,928,211 to Browning et al. (Browning) describes aprocess for scavenging H₂S, e.g., in aqueous drilling fluids, andpreventing metallic corrosion of iron drill pipe and the like by usingmetal compounds that form aqueous insoluble sulfides. Its metalcompounds contain metals with greater electromotive activity than Fe.Browning introduces the metal compounds into an aqueous drilling fluidand circulates the fluid in the well bore, either by prior preparationor in situ formation. Browning's metal compounds may include ZnCO₃,ZnCO₃·Zn(OH)₂, or Zn(OH)₂, or a dispersion of a zinc compound reactedwith an organic material. While Browning may use a heterogeneouscatalyst, it does not use a copper-containing catalyst, nor doesBrowning use a support.

U.S. Pat. No. 6,960,330, to Cox (Cox) describes compositions, methods,and systems useful for reducing a concentration of a contaminant, esp.H₂S, associated with a medium, which can be any substance or material,such as soil, water, air, and/or fluid. Cox's medium is treated withferric methylglycinediacetate, i.e., Fe-MGDA, and an oxidizing agent inamounts effective to oxidize at least a portion of the contaminant. Coxprefers reducing hydrogen sulfide content by adding Fe-MGDA and aperoxide to a medium with a hydrogen sulfide content; and reducing thehydrogen sulfide content in the medium. However, Cox does not indicateusing copper in its catalyst, Cox requires an oxidizing agent, Coxgenerally describes treating condensed phases, and Cox's system Fe-MGDAand/or oxidizing agent must be a fluid, including liquid, vapor, and/oraerosol form, but not heterogeneous.

U.S. Pat. No. 6,946,111 to Keller et al. (Keller) describes a processfor removing sulfur from a H₂S-containing gas stream, preferablyinvolving incorporating a short contact time catalytic partial oxidationreactor, a cooling zone, and a condenser into a conventional refinery orgas plant process, such as a natural gas desulfurizer, a hydrotreater,coker or fluid catalytic cracker, in which sulfur removal is needed inorder to produce a more desirable product. Keller's H₂S-containing gasstream is fed into a short contact time reactor where the H₂S ispartially oxidized over a suitable catalyst in the presence of O₂ toelemental sulfur and water. While Keller's system may optionally use asupport, such as Al₂O₃, ZrO₂, or partially stabilized (MgO) zirconia(PSZ), Keller's system uses Pt, Rh, Ni, Pd, Ru, and/or Ir, not copper,and Keller's system operates at 700° C. or above.

U.S. Pat. No. 6,495,117 to Lynn (Lynn) describes recovery of elementalsulfur from H₂S present in natural gases and other process gases bytreating the H₂S-containing gas in a series arrangement of aliquid-phase reactor; a furnace and a SO₂ absorber. Lynn feeds a H₂S-and a SO₂-containing gas into the liquid-phase reactor where they aredissolved into a solvent, such as polyglycol monoethers, diethers ofethylene glycol, diethers of propylene glycol, etc., and react in thepresence of a catalyst, such as a tertiary amine, pyridine,isoquinoline, etc., to produce elemental sulfur. Lynn's H₂S- and SO₂-gasfeed rates allow an excess of H₂S in the solvent, ensuring that reactionproducts include elemental sulfur and residual, unreacted H₂S, which isfed into a furnace, combusted into a SO₂-containing gas, which is fedinto a SO₂ absorber, where the SO₂ is extracted from the gas andrecycled back to the liquid phase reactor as the SO₂-containing gas.Lynn does not teach a copper catalyst, but instead a Claus catalyst(TiO₂ and/or Al₂O₃), and Lynn teaches using a glycol ether solvent and atertiary amine catalyst, and Lynn's system is homogeneous.

U.S. Pat. No. 5,215,728 to McManus (McManus US) describes a method andapparatus for the hydrothermal treatment of a catalytic polyvalent metalredox absorption solution, after absorption of the H₂S from an H₂Scontaining gas stream, to avoid substantial buildup of thiosulfatesalts, cyanide salts, and cyanide complexes in the catalytic polyvalentmetal redox solution. McManus US treats gas streams with both H₂S andHCN concurrently to destroy cyanide salts and complexes and converts H₂Sand by-product salts to elemental sulfur. McManus US does not use acopper catalyst, but rather Fe or V, and operates above 200° C. and 100bar. EP 257 124 A1 by McManus et al. (McManus EP) describes hydrogensulfide oxidation-catalyst regeneration process using an aqueouschelated polyvalent metal catalyst solution, like McManus US, butmodifies this with certain stabilizers, such as nitrilotriacetic acid(NTA).

U.S. Pat. No. 5,114,689 to Nagji et al. (Nagji) describes a system and aprocess with a primary adsorption bed with a regenerable, physicaladsorbent and an auxiliary sorption bed containing a chemisorbent forthe removal of sulfur compounds from a fluid stream, which processprovides for higher yields, higher purity and lower costs. Nagji uses azeolite support, optionally ion exchanged with zinc, copper or ironcations, but does not disclose anything beyond ZnO as its catalystmetal.

WO 2015/116864 A1 by Martin (Martin) discloses a family of metalchelates for use as an H₂S scavenger in asphalt, and the preparationthereof. Martin particularly uses amino acid metal chelates for reducingthe H₂S emissions of asphalt. While Martin's chelates may include B, Ca,Cr, Cu, Fe, Li, Mg, Mn, Mo, Na, K, Se, Sr, V, or Zn, particularly Cu orZn, Martin does not disclose heterogeneous catalysis. Moreover, Martinrequires an amino acid complex, uses no support, and adds catalysts intoa solid phase (or tar or Bingham fluid), rather than as a supportedcatalyst in a fluid, particularly water.

U.S. Pat. No. 9,587,181 to Lehrer et al. (Lehrer) describes that using acomposition including a transition metal salt and a water-solublealdehyde or precursor to scavenge H₂S present in aqueous fluids (e.g.produced water liquid streams), natural gas, and in oil and mixturesthereof (e.g. mixed production streams that contain all three phases),is better than either component when used alone. Lehrer's scavengercombination increases the reaction rate and the overall scavengingefficiency, i.e., capacity in comparison to the individual componentsused alone, in the same total amount. Examples of Lehrer's metal saltinclude Zn or Fe carboxylates, and an example of a water-solublealdehyde or water-soluble aldehyde precursor is ethylene glycolhemiformal. While Lehrer may describe suitable metal salts to includevarious Zn, Cu, Co, Mn, Fe, and/or Mo salt(s), Lehrer fails to disclosethat copper catalysts must be used, and Lehrer employs homogeneouscatalyst systems.

U.S. Pat. No. 9,480,946, to Ramachandran et al. (Ramachandran) describesa transition metal carboxylate scavenger that may be used to scavengecontaminants from systems from mixed production and/or gas, either dryor wet hydrocarbon gas. The contaminants scavenged or otherwise removedmay include, but are not necessarily limited to, H₂S, mercaptans,sulfides, and combinations thereof. Suitable non-limiting transitionmetal carboxylates in Hassan's scavenger include Zn octoate, Zndodecanoate, Zn naphthenate, and combinations thereof. Ramachandran mayuse salt(s) of zinc, iron, copper, cobalt, calcium, manganese, “etc.,and the like,” or mixtures of these, without any indication of theutility of copper particularly, nor its use without a carboxylate.Moreover, Ramachandran uses a homogeneous catalyst.

U.S. Pat. No. 5,700,438, to Miller (Miller) describes a process forremoving H₂S and mercaptans from gas streams, involving contacting suchgas streams with an aqueous solution of a copper complex of a watersoluble amine to form water insoluble copper sulfide and regenerate freewater soluble amine. Miller removes and recovers copper sulfide from thesystem. An additional copper complex of the water soluble amine isformed by reacting the regenerated water soluble amine with a coppercompound. Miller's process contacts H₂S gas streams with an aqueoussolution of a complex of copper with a water soluble amine to form waterinsoluble CuS, then regenerates free water soluble amine. While Miller'ssystem uses a copper-based catalyst, the catalyst lacks a support andmust be combined with an amine suitable to form a stable (tris)aminocopper complex but incapable of complexing copper sulfides, and Millerprefers not to use copper salts such as sulfates, nitrates, andchlorides.

U.S. Pat. No. 4,153,547 to McLean (McLean) discloses desulfurizing wellwater and making it palatable, by treating water with excess acidifiedcopper sulfate or other metal salt, precipitating and removing CuS fromthe water in a filter tank to obtain sulfur-free neutral water. ExcessCuSO₄ is precipitated as Cu(OH)₂ and removed in a filter. Mclean'sfilter tank automatically (or manually) backwashes to remove the copperresidues. While McLean uses a copper catalyst, McLean uses ahomogeneous, unsupported copper sulfate, and preferably at an acidic pH,e.g., no more than 4.

U.S. Pat. No. 4,880,609 to Naraghi (Naraghi) describes a solutionprocess for removing H₂S from a stream of natural gas. Sodium nitrite inthe solution serves as an oxidizing agent for the H₂S. Buffering anddefoaming agents are added. Absent a catalyst, Naraghi's process suffersfrom conversion of NO₂ ⁻ into NH₃ which conversion is suppressed by theincorporation of a transition metal chelate complex. Naraghi's metal ispreferably Cr, Cu, or Fe, or acceptably Mn, Ni, or V, and the chelatecomplex is preferably EDTA or TEA, or acceptably HEEDTA or NTA.Naraghi's metal chelate complex catalyzes the NaNO₂ oxidation of H₂S,markedly enhancing sulfur recovery as a precipitate in solution. Naraghidoes not use a support, discloses homogeneous catalysis, requiresnitrite as well as an (amine) chelate, and further requires a pH of 7.0to 11, preferably with a buffering agent.

U.S. Pat. No. 3,849,540 to Maddox et al. (Maddox) describes a processfor removing H₂S from natural gas comprising: (a) oxygenating an aqueoussolution consisting of a soluble catalyst consisting of transition metalcompounds including salts of Ni, Co, Mn, Cu, and Fe; (b) removingentrained but undissolved oxygen from the aqueous solution; and (c)treating hydrogen sulfide containing natural gas with the oxygen richaqueous solution of (b) at atmospheric pressure. Maddox prefers a Nicatalyst and uses a water-soluble transition metal compound in ahomogeneous system, and enough dissolved oxygen to stoichiometricallyreact with H₂S. Maddox does not describe using a support for itscatalyst.

U.S. Pat. No. 8,002,971 to Kozyuk (Kozyuk) describes processes andsystems for hydrodynamic cavitation-catalyzed oxidation ofsulfur-containing substances in a fluid. Carbonaceous fluid may becombined with at least one oxidant to form a mixture, then the mixtureis flowed through at least one local constriction in a flow-throughchamber at a sufficient pressure and flow rate to create hydrodynamiccavitation in the flowing mixture having a power density of betweenabout 3,600 and 56,000 kWatts/cm² measured at the surface of the localconstriction normal to the direction of fluid flow. The creation ofhydrodynamic cavitation in the flowing mixture initiates one or morechemical reactions that, at least in part, oxidize at least some of thesulfur-containing substances in the carbonaceous fluid. Kozyuk's systemmay include a device configured to mix a carbonaceous fluid andoxidant(s), a cavitation chamber configured to produce cavitationbubbles in the mixture, and an elevated pressure zone configured tocollapse the cavitation bubbles, thereby catalyzing oxidation of thesulfur-containing substances. While Kozyuk's optional metal catalyst mayinclude Fe (II or III), Cu (I or II), Cr (III or VI), Mo, W, or V ions,Kozyuk does not disclose a support. Kozyuk requires an oxidizing agent,such as a peroxide or ozone.

U.S. Pat. No. 6,444,185 to Nougayrede et al. (Nougayrede) describesprocess to recover H₂S, SO₂, COS, and CS₂ residues from the tail gas ofa sulfur recovery process. The tail gas is oxidized and hydrolyzed atfrom 180 to 700° C. to form a gas stream with substantially no COS orCS₂ and a concentration by volume of H₂S and SO₂ such that the H₂Sconcentration minus twice the SO₂ concentration is from 0.25 to 0.5%.Then the gas stream is passed over a Claus catalyst, e.g., aluminaand/or titanium oxide, to react H₂S with SO₂ to form sulfur and providea gas stream with substantially no SO₂. Nougayrede's resulting gasstream together with an O₂-containing gas is passed over an oxidationcatalyst, such as one of more oxides or salts of Ni, Co, Fe, Cu, Ag, Mn,Mo, Cr, W, or V, deposited on a support, such as bauxite, activatedalumina, silica, titania, zirconia, zeolites, or activated carbon toform sulfur and release a purified gas stream containing substantiallyno sulfur compounds. Nougayrede does not specifically combine Cu onalumina but discloses a multistage arrangement separately involvingminimum temperatures of 180 and 90° C., as well as at least two separatecatalysts, including a Claus catalyst.

U.S. Pat. No. 4,478,800 to Willem et al. (Willem) describes removingsulfur compounds from gases by passing the gases over an absorption masson an inert support having a specific surface area of more than 10 m²/g,contains metal oxides which react with H₂S to give metal-sulfurcompounds and at least 20% by weight of which metal oxides are presentin finely divided form with a particle size of less than 40 nm. Willem'sgases are passed at 5 to 800° C. over the support loaded with metaloxide, and the resultant support loaded with metal-sulfur compounds isregenerated by passing gases containing oxidizing agents over it.Willem's catalysts contain Cr, Co, Cu, Fe, Mn, V, Bi, Cd, Pb, Sn, asmetal oxides, and Willem describes a variety of supports, includingalumina, but Willem does not specify copper on alumina, and requires atleast 20 wt. % of its supported metal oxides having a particle size lessthan 40 nm, also preferring an at least 20 wt. % loading on its support.

U.S. Pat. No. 5,763,350 to Immel et al. (Immel) describes catalysts forremoving sulfur compounds almost completely from industrial gases. TheImmel catalysts are made by impregnating a suitable support with anoxide of at least one element selected from Group VIB of the periodictable and at least two other oxides of Group IB, IIB, VIB, and/or VIIIBelements. Industrial gases having sulfur compounds are brought intocontact with these catalysts under conditions to convert the sulfurcompounds to elemental sulfur, thus removing sulfur from the industrialgas. Immel discloses metal oxide catalysts, such as Cu, Zn, Cr, Mo, W,Fe, Co, or Ni, and requires a mixture of oxides of at least threemetals.

The article entitled “Titanium and Copper Oxide Based Catalysts for theIn-situ Reactions of Methanation and Desulfurization in the Removal ofSour Gases from Simulated Natural Gas” by Bakar et al. (Bakar), inMalay. J. Fund. App. Sci., 2009, 5(2), 293 (2289-599x), describescatalysts to achieve both low temperature and high conversion of sourgases. Bakar describes supported mixed metal oxide catalysts, preparedby impregnating the catalysts on alumina beads, for in-situ reactions ofH₂S desulfurization and CO₂ methanation at room temperature up to 200°C. Bakar reports 100% conversion of H₂S to elemental sulfur for all ofits catalysts at 100° C., but that methanation of CO₂ in the presence ofH₂S yielded 0.4% CH₄ over Fe/Zn/Cu/Ti—Al₂O₃ catalyst and 0.7% CH₄ overFe/Zn/Cu—Al₂O₃ catalyst at its maximum studied temperature of 200° C.XPS results indicated that spinel compounds of CuFe₂O₄ and Fe₃O₄ act asthe active sites on the Fe/Zn/Cu—Al₂O₃ and Fe/Zn/Cu/Ti—Al₂O₃ catalysts.The appearance of Fe³⁺—OH on Fe/Zn/Cu/Ti—Al₂O₃ catalyst increased itsH₂S desulfurization activity. Bakar reports that N₂adsorption-desorption analysis illustrated that 34% of the surface areaof Fe/Zn/Cu—Al₂O₃ catalyst was reduced, while Fe/Zn/Cu/Ti—Al₂O₃ catalystshowed reduction of 17% after catalytic testing, indicating deactivationof the catalysts from sulfur poisoning. Bakar requires at least twofurther metals in at least 10 wt. % when using a copper catalyst.

The conference paper entitled “Simultaneous removal of NO and SO₂ fromcombustion flue gases using copper oxide catalysts supported onCeO₂/γ-Al₂O₃,” from the EuropaCat IX, in Salamanca, Spain, in August of2009, by Bereketidou et al. (Bereketidou) discloses catalytic materialswith improved performance towards the simultaneous SO₂ and NO removalis, in any case needed, as the development of appropriate techniques forcombustion flue gases purification consists one of the principal topicsin environmental catalysis, particularly after stricter legislationbeing induced from European Union. The copper oxide (CuO) on CeO₂/Al₂O₃supported catalysts studied in this work, exhibit remarkableregenerative behavior and stability acting both as catalysts for nitricoxide (NO) selective reduction (SCR) and as sorbents for sulfur dioxide(SO₂) to form copper sulfate.

Bereketidou discloses copper oxide catalysts on alumina, but uses nomore than 8 wt. % copper and uses a 10 to 20 wt. %-Ce doped aluminasupport. Moreover, Bereketidou removes of NO and SO₂ from combustionflue gases, rather than removing H₂S, and operates at a temperature ofat least 150° C.

U.S. Pat. No. 7,837,964 to Wessel et al. (Wessel) describes a processesfor removing sulfur compounds from hydrocarbonaceous gases by usingcatalysts, with the exception of activated carbons and zeolites, whichcomprise Cu, Ag, Zn, Mo, Fe, Co, and/or Ni oxide(s), at from −50 to 150°C. and a pressure of from 0.1 to 10 bar. While Wessel may use aCuO-containing catalyst on a support, such as Al₂O₃, ZrO₂, SiO₂, etc.,the Wessel catalyst must contain at least 7.5 wt. % CuO as well as atleast a second metal, such as Mo, Zn, and/or Ba.

While useful approaches have been developed in the art, known systemsgenerally use complicated and/or homogenous systems, often usingchelates, oxidizing agents, stabilizers, and/or particular pH ranges. Aneed in the market remains for improved desulfurization and/orsweetening techniques, e.g., for treating hydrocarbon and/orpetrochemical gases, and apparatuses for such treatments.

SUMMARY OF THE INVENTION

Aspects of the invention include methods of reducing an initial H₂Scontent in a gas mixture, the methods comprising: passing the gasmixture, comprising H₂S and a hydrocarbon, through an aqueous suspensionof a solid catalyst comprising a copper salt impregnated on a support;and separating off a second gas with a reduced H₂S content relative tothe gas mixture, wherein the catalyst comprises more than 90 wt. %copper, based upon a total active metal content in the catalyst. Anypermutation of the features herein may be combined arbitrarily, as longas recognizable as technically feasible to persons of ordinary skill inthe art.

The copper salt may comprise at least 90% copper (II).

The copper salt may comprise, for example, Cu(NO₃)₂, CuF₂, CuCl₂, CuBr₂,CuCO₃, Cu(HCO₃)₂, CuSO₄, CuSiF₆, CuSeO₃, CuSeO₄, Cu(ClO₄)₂, Cu(ClO₃)₂,Cu(IO₃)₂, Cu(HCO₂)₂, Cu(BF₄)₂, Cu(O₂CCH₃)₂, [C₆H₁₁(CH₂)₃CO₂]₂Cu,Cu₂P₂O₇, C₂₆H₃₄O₆Cu, Cu(O₂C[CHOH]_(n)CH₂OH) where n is 2, 3, or 4,[Cu(NH₃)₄]SO₄, or a mixture of two or more of any of these. The coppersalt may preferably comprise Cu(NO₃)₂, CuCl₂, Cu(CO₃), Cu(HCO₃)₂, and/orCu(SO₄), esp. Cu(NO₃)₂, CuCl₂, and/or Cu(SO₄).

The support may comprise alumina, graphite, graphene, activated carbon,aluminosilicate, or a mixture of two or more of any of these. Thesupport may comprise at least 90 wt. % alumina, based on a total weightof the support, particularly α-Al₂O₃ or γ-Al₂O₃.

The catalyst may comprise the copper salt in an amount of from 10 to 20wt. %, based on a total weight of the solid catalyst, preferably in anamount of from 15 to 18 wt. %.

The reduced H₂S content may respectively be no more than 25 or 5 wt. %of the initial H₂S content within 220 or 250 minutes of contact with theaqueous suspension at a temperature in a range of from 15 to 40° C. anda pressure of 0.9 to 1.2 bar.

The gas mixture may further comprise CO₂. The hydrocarbon may comprisemethane, ethane, ethylene, propylene, propane, butane, butene,butadiene, and/or isobutylene. The hydrocarbon may comprise methane. Thegas mixture may be natural gas.

The aqueous suspension may comprise at least 90 wt. % water, based ontotal liquids in the aqueous suspension. The aqueous suspension may havea temperature in a range of from 5 to 45° C. Inventive methods may begenerally conducted under ambient conditions.

Aspects of the invention may provide (heterogeneous) desulfurizationcatalysts, comprising: a support comprising Al₂O₃ in an amount of atleast 95 wt. %, based upon total support weight, the support being inertto desulfurization at ambient conditions; copper (II) ions upon andimpregnated within the support in an amount of at least 95 wt. %, basedupon total catalytically active metals in the catalyst at the ambientconditions, and a liquid comprising at least 75 wt. % H₂O, based upontotal solvent weight.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the invention and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 shows a design of a process apparatus used for scavenging H₂Sfrom natural gas stream within the scope of the invention;

FIG. 2 shows the BET hysteresis curve for a Cu—Al₂O₃ catalyst usefulaccording to the invention, which catalyst may be prepared by a wetincipient method using a copper salt;

FIG. 3 shows a scanning electron microscopy (SEM) image of a Cu—Al₂O₃catalyst within the scope of the invention;

FIG. 4 shows a transmission electron microscopy (TEM) image of aCu—Al₂O₃ catalyst within the scope of the invention; and

FIG. 5 shows the x-ray diffraction pattern of a Cu—Al₂O₃ catalyst withinthe scope of the invention;

FIG. 6 shows a comparison between the H₂S breakthrough curves obtainedusing the three-phase (gas-liquid-solid) and the two-phase processes(gas-solid) with a Cu—Al₂O₃ catalyst within the scope of the invention;and

FIG. 7 shows the effect of flow-rate on H₂S breakthrough curves at 50,100, and 150 mL/min using a Cu—Al₂O₃ catalyst within the scope of theinvention, with the feed natural gas containing 100 ppmv H₂S going 50 mgcopper catalyst utilized in 10 mL of water at room temperature andatmospheric pressure.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Aspects of the invention provide methods of reducing an initial H₂Scontent in a gas mixture, the methods comprising: passing the gasmixture, comprising H₂S and a hydrocarbon, through an aqueous suspensionof a solid catalyst comprising a copper salt impregnated on a support;and separating off a second gas with a reduced H₂S content relative tothe gas mixture, wherein the catalyst comprises more than 75, 80, 85,90, 91, 92, 92.5, 93, 94, 95, 96, 97, 97, 97.5, 98, 99, 99.1, 99.5, or99.9 wt. % copper, based upon a total active metal content in thecatalyst. “Active metal” means those metals that react with the H₂Sunder the process conditions, preferably at no more than 100, 75, 50,45, 40, 35, 32.5, 30, 27.5, or 25° C., particularly under ambientconditions, i.e., STP.

The copper salt may comprise at least 90, 91, 92, 92.5, 93, 94, 95, 96,97, 97.5, 98, 99, 99.1, 99.5, 99.9, 99.99, 99.999, or 99.9999% copper(II). The copper salt may comprise or be selected from the groupconsisting of, for example, Cu(NO₃)₂, CuF₂, CuCl₂, CuBr₂, CuCO₃,Cu(HCO₃)₂, CuSO₄, CuSiF₆, CuSeO₃, CuSeO₄, Cu(ClO₄)₂, Cu(ClO₃)₂,Cu(IO₃)₂, Cu(HCO₂)₂, Cu(BF₄)₂, Cu(O₂CCH₃)₂, [C₆H₁₁(CH₂)₃CO₂]₂Cu,Cu₂P₂O₇, C₂₆H₃₄O₆Cu, Cu(O₂C[CHOH]_(n)CH₂OH) where n is 2, 3, or 4,[Cu(NH₃)₄]SO₄, or a mixture of two or more of any of these. The coppersalt may preferably comprise Cu(NO₃)₂, CuCl₂, Cu(CO₃), Cu(HCO₃)₂, and/orCu(SO₄), esp. Cu(NO₃)₂, CuCl₂, and/or Cu(SO₄₎. The copper salt shouldgenerally have some solubility in water or a solvent system, in order tobe impregnated into the support.

The support may comprise alumina, graphite, graphene, activated carbon,aluminosilicate, or a mixture of two or more of any of these. Thesupport may comprise at least 90, 91, 92, 92.5, 93, 94, 95, 96, 97,97.5, 98, 99, 99.1, 99.5, 99.9, 99.99, 99.999, or 99.9999 wt. % alumina,based on a total weight of the support, though α-Al₂O₃ or γ-Al₂O₃ haveshown particular utility. The support may be a mixture of alumina types.

The catalyst may comprise the copper salt in an amount of from 10 to 20,12.5 to 19, 15 to 18.5, 16, 17, or 18 wt. %, based on a total weight ofthe solid catalyst.

The reduced H₂S content may respectively be no more than 25 (or 5) wt. %of the initial H₂S content within 220 (or 250) minutes of contact withthe aqueous suspension at a temperature in a range of from 15 to 40° C.and a pressure of 0.9 to 1.2 bar. The reduction of H₂S for exemplary twoor three-phase arrangements can be seen in FIG. 6 , which shows thatpassing gases over a solid bed more rapidly begins take up, but thethree-phase system ultimately more rapidly removes the H₂S. H₂S removalmay be at least 75, 80, 85, 90, 91, 92, 92.5, 93, 94, 95, 96, 97, 97.5,98, 99, 99.1, 99.5, or 99.9 wt. %, relative to the initial H₂S content,within 325, 315, 310, 305, 300, 290, 275, 265, 250, 245, 240, 235, 230,225, 220, 215, 210, or 200 minutes of exposure to the three-phase systemunder ambient conditions. These rates can be increased by a factor of1.1, 1.2, 1.25, 1.33, 1.4, 1.45, 1.5, 1.6, 1.67, 1.75, 1.85, 2, 2.25,2.5, 2.75, 3, 3.5, 4, 5, 6, 7.5, or even 10, by increasing the reactiontemperature from 25 to 35, 50, 75, 100, 125, 150, 175, 200, 250, 300,400, 500, 600, 750, or 900° C.

The gas mixture may further comprise CO₂, and the CO₂ may be present in2, 5, 10, 15, 20, 25, 30, 40, 50, 60, 65, 75, 85, 100, 150, 200,250-fold the amount, or more, of the H₂S based on moles. The gas mixturemay further contain N₂, CO, Ar, H₂, He, NH₃, O₂, and/or O₃, but mayexclude any or all of these.

The hydrocarbon may comprise methane, ethane, ethylene, propylene,propane, butane, butene, butadiene, and/or isobutylene. The gas mixturemay be syn gas. The hydrocarbon may further or alternatively includedimethyl ether, ethyl methyl ether, neopentane. The hydrocarbon maycomprise at least 25, 33, 45, 50, 60, 65, 70 75, 80, 85, 90, 92.5, 95,97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % methane, ethane, ethylene,propylene, propane, butane, butene, butadiene, and/or isobutylene, basedon the total hydrocarbons. The gas mixture may be natural gas. Thehydrocarbon may contain ethane and ethylene, or propane and propylene

The aqueous suspension may comprise at least 75, 80, 85, 90, 92.5, 95,97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % water, based on total liquids inthe aqueous suspension, but may, in addition or in place of water,contain ethylene glycol, methanol, ethanol, propanol, isopropanol,n-butanol, ethyl acetate, pet ether, pentane, hexane(s), decalin, THF,dioxane, toluene, xylene(s), and/or o-dichlorobenzene.

The aqueous suspension may have a temperature in a range of from 5 to45, 10 to 40, 15 to 35, 20 to 30, or 22.5 to 27.5° C. Inventive methodsmay be conducted under ambient conditions, e.g., having suchtemperatures or pressures of no more than 1.5, 1.4, 1.3, 1.2, 1.1,1.075, 1.05, 1.04, 1.03, 1.025, 1.02, or 1.015 bar.

Aspects of the invention may provide (heterogeneous) desulfurizationcatalysts, comprising: a support comprising Al₂O₃ in an amount of atleast 90, 91, 92, 92.5, 93, 94, 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or99.9 wt. %, based upon total support weight, the support being inert todesulfurization at ambient conditions; copper (II) ions upon andimpregnated within the support in an amount of at least 90, 91, 92,92.5, 93, 94, 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, 99.9, 99.99, or99.999 wt. %, based upon total catalytically active metals in thecatalyst at the ambient conditions, and a liquid comprising at least 50,60, 70, 75, 80, 85, 90, 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9wt. % H₂O, based upon total solvent weight. In addition or in place ofwater, the liquid may contain ethylene glycol, methanol, ethanol,propanol, isopropanol, n-butanol, ethyl acetate, pet ether, pentane,hexane(s), decalin, THF, dioxane, toluene, xylene(s), and/oro-dichlorobenzene. That is, as above, the “aqueous” suspension maycontain a minority fraction of, or even no, water. The support maycontain alternate materials, as above, but generally need not use dopedor ion-exchanged alumina (such as those modified with Ce) or zeolites,and may use unmodified (commercially available) materials.

Any of the following features, like those above, may be explicitlycombined in any permutation in catalysts within the scope of theinvention. Inventive catalysts need not, but may largely excludealdehydes, i.e., comprise no more than 25, 20, 15, 10, 5, 4, 3, 2, 1,0.5, 0.1, 0.001, or 0.0001 wt. % or no more than trace detectableamounts of aldehyde(s). Likewise or separately, the catalysts maycomprise no more than 25, 20, 15, 10, 5, 4, 3, 2, 1, 0.5, 0.1, 0.001, or0.0001 wt. % or no more than trace detectable amounts of carboxylate(s).Likewise or separately, the catalysts may comprise no more than 25, 20,15, 10, 5, 4, 3, 2, 1, 0.5, 0.1, 0.001, or 0.0001 wt. % or no more thantrace detectable amounts of amine(s), esp. tertiary amine(s), and/oramino acid(s).

Aside from copper (ions) amongst the active catalyst metals, inventivecatalysts need not, but may contain fewer than 50, 33, 25, 20, 15, 10,7.5, 5, 2.5, 2, 1, or 0.1 wt. %, relative to total active metals, of Zn,Co, W, Ca, Cd, Sn, Mn, Li, Mg, Se, Sr, Fe, Pt, Rh, Ni, Pd, Ru, V, and/orIr. Inventive catalysts need not, but may contain fewer than 50, 33, 25,20, 15, 10, 7.5, 5, 2.5, 2, 1, or 0.1 wt. %, relative to total activemetals, of any other metals besides copper. Inventive catalysts mayavoid, i.e., contain no Claus catalyst (TiO₂ and/or Al₂O₃), or maycontain no more than 10, 5, 2.5, 1, 0.5, 0.1, 0.001 wt. %, relative tototal solid catalyst weight, of Claus catalyst(s). Inventive catalystsmay contain fewer than 10, 5, 2.5, 1, 0.5, 0.1, 0.001 wt. % metaloxides, and/or less than 7.5, 5, 2.5, 1, or 0.5 wt. % CuO, relative tototal solid catalyst weight. The supports may contain less than 10, 5,2.5, 1, 0.5, 0.1, 0.001 wt. % CeO₂ and/or any forms of cerium insupport, relative to total support weight. Inventive catalysts maycontain no more than 33, 30, 27.5, 25, 22.5, 21, or 20 wt. % activemetal in the catalyst, relative to a total weight of metal and support.

While not necessarily, inventive catalysts (or compositions comprisingthe desulfurization/de-H₂S catalyst may comprise no nitrite, or maycomprise no more than 40, 33, 25, 20, 15, 10, 7.5, 5, 4, 3, 2, 1, or 0.5wt. %, relative to the total solid catalyst/composition weight, ofnitrite. Copper nitrites may be selectively excluded. Likewise orseparately, inventive catalysts/compositions may contain no more than33, 25, 20, 15, 10, 7.5, 5, 4, 3, 2, 1, or 0.5 wt. %, relative to thetotal solid catalyst/composition weight, of oxidizing agents, e.g.,peroxide(s), hydroperoxide(s), peracid(s), and/or ozone. Inventivecatalysts/compositions may comprise no more than 40, 33, 25, 20, 15, 10,7.5, 5, 4, 3, 2, 1, or 0.5 wt. %, relative to the total solidcatalyst/composition weight, of amino acid, aspartate, carbonate,citrate, gluconate, sulfate, and/or yeast, or may entirely avoid any orall of these, for example, beyond inevitable traces. Inventive catalystsmay comprise no chelates, e.g., amine and/or phosphorous-containingchelates, and/or monodentate and/or bidentate and/or tridentatechelates, or may comprise no more than 40, 33, 25, 20, 15, 10, 7.5, 5,4, 3, 2, 1, or 0.5 wt. %, relative to the total solidcatalyst/composition weight, of any or all such chelates.

Inventive reactions, reactors, treatment vessels, and/or reactionsystems may not require stirring at all, or may be carried out withshearing no more than 20,000, 10,000, 5,000, 2,500, 1,000, 750, 500,400, 300, 250, 200, 150, 125, 100, 75, 50, 25, or 10 Hz. Inventivereactions, reactors, treatment vessels, and/or reaction systems mayemploy baffles or static flow agitators/interrupters.

Apparatuses for sweetening relevant gas mixtures may include: a firstcolumn and a second column, each being substantially vertical andparallel to each other, e.g., no more than 80, 85, 88, or 89° skewbetween their angular projections; an upper connector; and a lowerconnector. While not necessarily 90° from the ground (or a base), thevertical columns will generally be within 10, 5, 2, or 1° oforthogonality to the base, and are referred to as “vertical” for brevityherein. The connectors may connect the first and second vertical columnsto create a loop, with an upper connector going from an upper portion ofthe first vertical column to an upper portion of second vertical column(generally lower in height than the interface at the first verticalcolumn). The lower connector may go from a lower portion of the secondvertical column to a lower portion of first vertical column (generallylower in height than the interface at the second vertical column). Theupper connector may be inclined downward from the first to secondvertical column, and/or the lower connector may be inclined upward fromthe first to second vertical column, e.g., making a trapezoidalelevational view, as seen in FIG. 1 . The upper and/or lower connectormay be angled, negatively or positively, within 45, 30, 22.5, 15, 7.5,5, 3, or 1° of a parallel to the base of the apparatus, but may even beparallel to the base (orthogonal to the vertical column). The reactivelength of the first vertical column(s) may have a ratio to that of thesecond vertical column(s) in a range of from 5 to 1:1, 4 to 1.1:1, 3 to1.2:1, 2 to 1.25:1, or 1.75 to 1.3:1. That is, the first vertical columnwill generally have a greater reactive length than the second, thoughthe first and second vertical column(s) may have the same physicallength/height. Typically, only the first vertical column will use phaseseparators, such as fritted glass barriers, at least towards the bottomof the first vertical column, where a gas inlet may be located. Thefirst and second vertical column(s) may have identical cross-sectionalareas in flow direction, or the cross-sectional areas may be, forexample, 1:1.05 to 3, 1:1.1 to 2.5, 1:1.25 to 2, which ratios may bemodified based upon the relative count of first and second verticalcolumn(s).

Inventive apparatuses may include 1, 2, 3, 4, or 5 further connector(s)along the height of the vertical columns. The upper and lower connectorswill generally be attached at no more than 25, 20, 15, 10, or 5%(length) from the first vertical column bottom and/or top, based on theentire length of the first vertical column. The upper and lowerconnectors will generally be attached at no less than 10, 15, 20, 25,30, 35, or 40% (length) from the second vertical column bottom and/ortop, based on the entire length of the second vertical column. The upperand lower connector(s) may have identical cross-sectional areas to eachother and/or first vertical column(s) and/or second vertical column(s),in flow direction, or the upper to lower connector cross-sectional areasmay be, for example, 1:0.5 to 2, 1:0.75 to 1.5, 1:0.9 to 1.25, with thefirst and/or second vertical column(s) generally having 1.1, 1.25, 1.5,2, or 2.5-fold greater cross-sectional areas. A diameter of the verticalcolumn(s) may be in a range of from 1 cm to 3 m, depending upon theapplication, e.g., at least 0.5, 0.75, 1, 1.5, 2, 3, 5, 10, 25, 50, or100 cm, and/or up to 5, 4, 3, 2.5, 2, 1.5, 1.25, 1, 0.75 m.

The vertical columns and/or connectors generally contain a liquid orgas/liquid phase, such as water, an aqueous solution, an organicsolution, or a split/emulsified organic-aqueous mixture, including theinventive catalyst suspended therein. Roughly 20 to 50 wt. % of theliquid/catalyst mixture may be contained in the first verticalcolumn(s), with 20 to 40 wt. % in the second vertical column(s), and 20to 30 wt. % in the connectors. The liquid/catalyst suspension, whenspent, may collect in a bottom portion of the second vertical column(s),which may be below the bottom connector interface with the secondvertical column and may constitute up to 2, 5, 10, 15, or 20% of thesecond vertical column's volume. The feed gas for sweetening may be ledthrough a column of liquid/catalyst suspension occupying 20 to 99, 33 to95, 50 to 90, 60 to 85, or 66 to 75% of the first vertical column'stotal volume. The liquid/catalyst suspension may gather in the upperconnector, optionally behind a valve, and/or may flow through, generallydownwards in the upper connector into the second vertical column, andagain downwards in the lower connector to a lower portion of the firstvertical column, to be driven upwards by the gas feed and/or one or morepumps.

The spent catalyst/liquid may be held up with a valve and/or may be ledoff to a regeneration, e.g., as set forth in U.S. Pat. No. 8,002,971 or8,071,146, each of which is incorporated in its entirety by referenceherein. Plant layouts including inventive apparatuses may advantageouslyavoid, e.g., amine contactors and/or basic sweeteners, or may allow 5,10, or 20 wt. % less base to be used in sweetening.

Inventive apparatuses may include 1, 2, 3, 4, 5, or more of the verticalcolumn(s), connector(s), gas inlet(s), gas outlet(s), catalyst inlet(s),and/or catalyst outlet(s), and the duplicated and/or multiple elementsmay be unified in any manner advantageous for the given application,e.g., 5 first vertical columns into 1 or 2 common upper connector(s)into, e.g., 4 or 3 second vertical column. The columns and connectorsmay have circular, square, and/or ovular cross-sections, and mayinclude, e.g., annular portions inflecting radially inwardly and/oroutwardly towards the cross-sectional center. A flux of the feed gasthrough the liquid/catalyst suspension may be in a range of from 0.1 to25, 0.5 to 15, 1 to 10, 1.5 to 7.5, or 2 to 5 mL/s for a 1 cmcross-sectional diameter vertical column.

Inventive methods may operate at pHs in the neutral range and/or above4, though the efficiency of the H₂S removal should be within 90% acrossthe pH range of 2 to 13, 3 to 11, 4 to 10, 5 to 8, or 6 to 7.5. Noparticular considerations need to be taken regarding pH, and acceptablereaction pHs will generally be at the ambient/natural conditions ofwater available. Inventive methods may operate under 700, 500, 350, 200,180, 90, or 40° C. The method may preferably be operated at theenvironmental conditions at the site of implementation, e.g., at orwithin 1000, 750, 500, 250, 200, 150, 100, 50, or 20 meters of a naturalgas source, an oil source, a hydrocarbon platform, an LNG storagefacility, an LNG transport tanker, a petrochemical plant, a refinery, apolymerization reactor, a cracker, a PSA, an MTG plant, and/or an MTOplant.

Aspects of the invention provide two or three-phase processes forscavenging H₂S from hydrocarbon gas mixtures, i.e., a gas comprising ahydrocarbon and H₂S, such as a sour natural gas stream, syn gas,cracking off-gases, exhausts, crude or at least partially purifiedmethane, ethane, ethylene, propylene, propane, butane, butene,butadiene, and/or isobutylene gas(es). Gas phases may comprise H₂S, CO₂,and a hydrocarbon, e.g., methane. Liquid phases within the invention,when present, may comprise or consist essentially of water, i.e., atleast 75, 80, 85, 90, 91, 92, 92.5, 93, 94, 95, 96, 97, 97.5, 98, 99,99.1, 99.5, 99.9, 99.99, 99.999, or 99.9999 wt. % of a total weight ofthe liquid phase weight being water. Solid phases generally contain acopper catalyst impregnated on alumina, wherein the catalyst metal maycomprise at least 75, 80, 85, 90, 92.5, 95, 97.5, 98, 99, 99.1, 99.5, or99.9 wt. % Cu relative to total metals, and/or the support may comprisealumina in amount of at least 75, 85, 90, 92.5, 95, or 97.5 wt. % of thesupport total weight. The gas(es) may be bubbled through a two-phase bedand/or into the three-phase column, contacting the dispersed solidphase, i.e., supported copper-based catalyst, in an air or at leastpartially inert atmosphere or within the bulk of liquid phase, e.g.,water, an aqueous mixture/solution, an organic phase, etc.

Concentrations of H₂S in exit gas stream(s) may be monitoredcontinuously, enabling the construction of H₂S breakthrough curves andthe calculation of the amount of H₂S scavenged.

The copper-based catalyst may be prepared by a wet incipient method,i.e., capillary impregnation or dry impregnation, typically comprisingdissolving active metal precursor(s) in an aqueous or organic solution,adding the metal-containing solution to a catalyst support, optionallyhaving the same pore volume (or within 50, 33, 25, 15, 10, or 5%) as thevolume of the added solution, and allowing capillary action to draw thesolution into the pores. In wet incipient methods excess solution(beyond the support pore volume) can cause the solution transport tochange from a capillary action process to a slower diffusion process.Catalysts can then be dried and calcined to drive off the volatilecomponents within the solution, depositing the metal on the catalystsurface. Maximum loading is generally limited by the solubility of theprecursor in the solution. Concentration profiles of impregnatedcompound(s) depend on mass transfer within the pores during impregnationand drying.

Inventive catalysts are generally selective towards the acid gas, i.e.,H₂S, and thus the presence of hydrocarbon gases in the gas feedgenerally will not affect the efficacy of inventive catalyst(s).Selectivities may be in a range of 1.5 to 100, 2 to 50, 3 to 25, basedon relative kinetic reaction rate constants. Three-phase processesshowed surprising superiority over two-phase (gas-solid) fixed-bedprocesses in terms of the amount of H₂S scavenged and breakthrough time.Inventive two and three-phase processes are effective at ambientconditions, and the catalyst is typically regenerable.

Aspects of the invention may provide (i) complete dissolution (orleaving less than 15, 10, 7.5, 5, 2.5, 2, 1, 0.1, 0.01, 0.001, or 0.0001wt. %, based on the feed gas, or even no more than detectable limits) ofH₂S from a hydrocarbon gas stream, such as natural gas, into thesolid-liquid system; (ii) the use of three phase sorbent/catalyst methodand/or apparatus to scavenge H₂S, i.e., gas/liquid/solid; (iii) use ofcopper impregnated on alumina as catalyst for reduction of H₂S inaqueous solution; and/or (iv) synergetic effect(s) ofadsorption-absorption of H₂S on the rate of H₂S reduction.

Inventive methods may involve loading one or more copper salts, such asCu(NO₃)₂, CuF₂, CuCl₂, CuBr₂, CuCO₃, Cu(HCO₃)₂, CuSO₄, CuSiF₆, CuSeO₃,CuSeO₄, Cu(ClO₄)₂, Cu(ClO₃)₂, Cu(IO₃)₂, Cu(HCO₂)₂, Cu(BF₄)₂,Cu(O₂CCH₃)₂, [C₆H₁₁(CH₂)₃CO₂]₂Cu, Cu₂P₂O₇, C₂₆H₃₄O₆Cu,Cu(O₂C[CHOH]_(n)CH₂OH) where n is 2, 3, or 4, [Cu(NH₃)₄]SO₄, etc., ontosurfaces of support(s) comprising alumina, e.g., γ-Al₂O₃, α-Al₂O₃,graphite, graphene, activated carbon, or aluminosilicates (with variousalumina-silica ratios). Loading percentages of the catalyst on thesupport(s) may be as high as 33, 25, 20, 18, 15, 12.5, or 10 wt. %,considering all catalytic metals on the support (or in the catalystcompound). Catalyst precursor solutions may comprise water in at least75, 80, 85, 90, 92.5, 95, 97.5, 98, 99, 99.1, 99.5, or 99.9 or more wt.%, but may also comprise water mixed with a chelating agent, or coppercomplexes, such as copper(II)-n,n-diethylethylenediamine,[CuLn]-(BAr₄)₂—wherein Ln is ligand, B is boron, and Ar is aryl etc.).

Inventive catalysts may be used (1) directly in a fixed bed adsorbentfor scavenging H₂S from sour gas stream, i.e., 50, 60, 70, 75, 80, 85,90, 95, 98, 99, 99.99 or more % solvent free; (2) mixed in a liquid(sorbent solution), the sour gas being allowed to bubble through thesorbent solution; (3) in counter-current circulation of the mixedcatalyst-solution with the sour gas stream; and/or (4) co-currentcirculation of the mixed catalyst-solution with the sour gas stream.Counter-current and co-current circulations may be implemented inparallel and/or in series. Exit gas concentrations may be measured as afunction of time and breakthrough curves may be recorded, withdifferences between feed and exit stream H₂S concentrations representingthe amount of H₂S scavenged.

In an inventive plant arrangement, an optionally preheatedH₂S-containing feed may flow through a heater where the feed mixture istotally vaporized and heated to the required temperature before enteringthe reactor and flowing through a fixed-bed and/or liquid layer ofinventive catalyst where the hydrodesulfurization (HDS) reaction takesplace. The HDS reaction products may be at least partially cooled, ifnecessary, by flowing through the heat exchanger where the reactor feedwas preheated and then through, e.g., a water-cooled heat exchangerbefore optional (de)pressurization and/or gas separation. Rather than,or in addition to, routing gas from a gas separator vessel, through anamine contactor for removal of the reaction product H₂S, this gas may bepassed through at least one inventive sweetening apparatus. The H₂S-freegas may then be sent to further processing and/or an end use.

Sour gas, e.g., from a stripper or from a hydrocarbon source may containH₂, CH₄, C₂H₆, H₂S, C₃H₈, C₃H₆, C₄H₁₀, butene(s), pentene(s), and/orheavier components. Sour gas, particularly containing H₂S, butoptionally also organic thiols, sulfides, disulfides, thiophenes, andsulfur oxides, from basically any source may be sent to a gas processingplant comprising an inventive sweetening apparatus for removal of theH₂S. After the H₂S is removed in the inventive sweetening apparatus, andoptionally further in an amine gas treating unit, the sweetened gas maybe optionally passed through a series of distillation towers to recoverand/or isolate hydrocarbon components, such as methane, ethane,ethylene, propane, propylene, butane, pentane, and/or heaviercomponents. The H₂S removed/recovered by the inventive sweeteningapparatus(es), and any amine gas treating unit(s), may be subsequentlyconverted to elemental sulfur in a Claus Process unit or to sulfuricacid in a wet sulfuric acid process and/or in a conventional ContactProcess.

WORKING EXAMPLES Example 1

A fixed mass (0.05 g) of solid copper catalyst is placed in a 1.5 mmjacketed glass tube. Glycol solution was circulated to maintain thedesired reaction temperature (e.g., room temperature of −22° C.)±+1° C.Synthetic natural gas streams containing variable concentrations of H₂S(50, 100 ppmv), CO₂ (1000, 2000 ppmv) and the balance methane wereintroduced at different flowrates. The pressure drop across the catalystbed was monitored using a digital pressure gauge. The concentrations ofinlet and outlet H₂S were measured continuously using an RAE multi-gasmeter.

Example 2

The same procedure as in Example 1 was repeated but pure deionized water(10 mL) was used as a blank solution. The water was maintained in a 1-cmID fretted glass tube.

Example 3

The same procedure as in Example 2 was repeated where copper-basedcatalyst-water slurry was used instead of pure water. The desired amountof copper-based catalyst (0.05 g) was dispersed in 10 mL deionizedwater.

Example 4

The same procedure as in Example 2 was repeated but a mixture of coppercomplex (0.05 g) was used instead of pure water.

Table 1

TABLE 1 Surface area and pore size analysis for Cu—Al₂O₃ catalystProperty Value BET surface area: 62.5383 m²/g BJH adsorption cumulativesurface area of pores 68.097 m²/g between 17.000 and 3000.000 Ådiameter: Å and 3000.000 Å diameter: Adsorption average pore width (4V/Aby BET): 202.9286 Å width (4V/A by BET): BJH adsorption average porediameter (4V/A): 175.833 Å BJH desorption average pore diameter (4V/A):153.486 Å

Referring now to the drawings, wherein like reference numerals designateidentical or corresponding parts throughout the several views.

Example 5

Process of scavenging H₂S. A laboratory scale process of scavenging H₂Sby a circulating fluidized slurry of Cu—Al₂O₃ is exemplified in FIG. 1 .On large scale, gas stream(s) containing H₂S may be introduced at one ormore locations at the bottom of the fluidized reactor, i.e., below 33,25, 20, 15, 10, 7.5, 5, 4, 3, 2, and/or 1% of the reactor height, wherethe slurry containing the Cu—Al₂O₃ and optional solvents/solutions maycontact the gas stream(s) and be carried upward. Sweetened gas may thenbe passed through a separator element (2, upper), such as fritted glass,gauze, and/or membrane(s), etc., to one or more analyzers and/or anoutlet (1). The catalyst slurry may be accumulated in an inclinedportion, such as a tube, and a check slurry valve (4) may allow partialflow to maintain a specified solid-liquid ratio. For example, thesolid-liquid ratio, measured as the percent solid catalyst mass per massof liquid, may be in a range of from 0.01 to 5, 0.05 to 5, 0.1 to 4,0.15 to 3.5, 0.2 to 3, 0.25 to 2.5, 0.3 to 2, 0.33 to 1.75, 0.35 to 1.5,0.4 to 1.25, 0.425 to 1, 0.45 to 0.75%, e.g., 0.5 mg of catalyst may beused in 10 g of liquid. The accumulated slurry or used catalyst can beallowed to flow downwards by the effect of gravity and may be mixed withfresh catalyst and/or at least partially regenerated. The Cu—Al₂O₃catalyst may be added batch-wise and/or continuously in a catalyst inlet(7) and may be added to tailor the efficiency of scavenging H₂S gasand/or heat transfer, for example. Part of the slurry catalyst may beaccumulated in a spent catalyst container through a valve (5), and/orsent to a recycle, while non-separated catalyst may be returned tocontact the inlet gas stream (3) and cycled again with the gas stream.Spent catalyst (6) may be regenerated in a separate process by washingwith oxidizing agent such as nitric acid or hydrochloric acid, washed,e.g., with water, and used again.

FIG. 2 shows a BET hysteresis loop for a supported Cu—Al₂—O₃ catalystaccording to the invention. The catalyst was prepared by wet incipientmethod using a copper salt. FIGS. 3, 4, and 5 respectively shows ascanning electron microscopy (SEM) image, transmission electronmicroscopy (TEM) image, and x-ray diffraction pattern, of the Cu—Al₂O₃catalyst.

As seen on 5 micron scale in FIG. 3 , inventive catalyst may take asubstantially amorphous, fractal, and/or flocculent morphology, withfuzzy outcroppings upon agglomerated masses of irregular shape. Theoutcroppings may have a somewhat snow-flake like appearance with roughly1 to 3 micron widths and 2 to 5 micron lengths in 2D. FIG. 4 revealsthat the catalyst particles have an irregular shape on 200 nm scale,with (in 2D) ovular and/or circular volumes of greater density spacedirregularly throughout the morphology, with occasional agglomerations of2 to 3 spheroids, spaced by 100 nm or more from other spheroids and/oragglomerations. The 200 nm scale TEM shows a jagged outer surface of thecatalyst particle/flake, apparently overlaid, with approximately 400 to600 micron span in its longest dimension and some 200 to 300 micron spanperpendicular to the longest dimension.

FIG. 5 shows 2θ peaks in the XRD of inventive catalyst at ˜19° (fullwidth at half maximum—FWHM ˜5, 0.2 relative intensity—r.i.), ˜33° (FWHM˜4, 0.3 r.i.), ˜36° (FWHM ˜4, 0.6 r.i.), ˜38° (FWHM ˜2, 0.4 r.i.), ˜43°(FWHM ˜1, 0.4 r.i.), ˜45° (FWHM ˜1, 1 r.i.), ˜46° (FWHM ˜2 withshoulder, 0.65 r.i.), ˜52° (FWHM ˜2, 0.35 r.i.), 61° (FWHM ˜4, 0.25r.i.), ˜63° (FWHM ˜3, 0.25 r.i.), ˜67° (FWHM ˜3, 0.8 r.i.), and ˜76°(FWHM ˜2, 0.25 r.i.). FIG. 6 shows a comparison between the H₂Sbreakthrough curves obtained using three-phase and two-phase processes.The amount of catalyst is very comparable, i.e., within 95 wt. % of eachother, 4.7% for both processes, dispersed in 10 mL water, and each sournatural gas feed contained 100 ppmv H₂S. The scavenging process wasconducted at room temperature and atmospheric pressure. While the solid,two-phase application shows and earlier adsorption of H₂S and a gradual,almost linear adsorption process, the three-phase, catalyst slurried inliquid adsorbed the H₂S in roughly 100 minutes, while the two-phaseapproach needed about 600 minutes to accomplish the same H₂S removal.

FIG. 7 shows the effect of sour gas flow rate on the H₂S breakthroughcurve, whereby the sour natural gas feed contained 100 ppmv H₂S and theamount of supported copper catalyst utilized was about 50 mg. Thecatalyst is dispersed in 10 mL water. The scavenging process wasconducted at room temperature and atmospheric pressure.

Numerous modifications and variations of the present invention arepossible in light of the above teachings. It is therefore to beunderstood that within the scope of the appended claims, the inventionmay be practiced otherwise than as specifically described herein.

REFERENCE SIGNS

-   1 gas outlet-   2 phase separator, e.g., fritted glass-   3 gas inlet-   4 check valve-   outlet valve-   6 catalyst outlet, e.g., spent catalyst or regeneration feed-   7 catalyst inlet

The invention claimed is:
 1. A method of reducing an initial H₂S content in a gas mixture, the method comprising: passing the gas mixture, comprising H₂S and a hydrocarbon, through an aqueous suspension of a solid catalyst comprising a copper salt impregnated on an α-Al₂O₃ support; and separating a second gas from the gas mixture passed through the aqueous suspension comprising at least 90 wt. % of liquid water, the second gas having an at least 95% reduced H₂S content relative to the gas mixture, wherein the solid catalyst comprises at least 95 wt. % copper, based upon a total active metal content in the solid catalyst, wherein at least 90 mol % of the copper in the copper salt is copper (II), wherein the copper salt is selected from the group consisting of Cu(NO₃)₂, CuCl₂, Cu(CO₃), Cu(HCO₃)₂, Cu(SO₄), and mixtures thereof, wherein the solid catalyst comprises less than 1 wt. % CuO and less than 1 wt. % Fe, based upon the total active metal content in the solid catalyst, wherein the support comprises at least 90 wt. % alumina, based on a total weight of the support, wherein the catalyst comprises the copper salt in an amount of from 15 to 18 wt. %, based on a total weight of the solid catalyst, and wherein the solid catalyst comprises no activated carbon.
 2. The method of claim 1, wherein at least 99 mol % of the copper in the copper salt is copper (II).
 3. The method of claim 1, wherein the gas mixture further comprises CO₂.
 4. The method of claim 1, wherein the hydrocarbon comprises methane, ethane, ethylene, propylene, propane, butane, butene, butadiene, and/or isobutylene.
 5. The method of claim 1, wherein the hydrocarbon comprises methane.
 6. The method of claim 1, wherein the gas mixture is natural gas.
 7. The method of claim 1, wherein the aqueous suspension comprises at least 95 wt. % water, based on total liquids in the aqueous suspension.
 8. The method of claim 1, wherein the aqueous suspension has a temperature in a range of from 5 to 45° C.
 9. The method of claim 1, conducted under ambient conditions.
 10. The method of claim 1, wherein the gas mixture is syn gas.
 11. The method of claim 1, wherein the solid catalyst comprises at least 99 wt. % copper, based upon a total active metal content in the solid catalyst.
 12. The method of claim 11, Wherein the gas mixture is natural gas.
 13. A method of reducing an initial H₂S content in a gas mixture, the method comprising: passing the gas mixture, comprising H₂S and a hydrocarbon, through an aqueous suspension of a solid catalyst comprising a copper salt impregnated on a support; and separating a second gas from the gas mixture passed through the aqueous suspension comprising at least 90 wt. % of liquid water, the second gas having an at least 95% reduced H₂S content relative to the gas mixture, wherein the solid catalyst comprises at least 95 wt. % copper, based upon a total active metal content in the solid catalyst, wherein at least 90 mol % of the copper in the copper salt is copper (II), wherein the copper salt comprises CuCl₂ and/or Cu(NO₃)₂ and optionally further at least one selected from the group consisting of Cu(CO₃), Cu(HCO₃)₂, and Cu(SO₄), wherein the solid catalyst comprises less than 1 wt. % CuO and less than 1 wt. % Fe, based upon the total active metal content in the solid catalyst, wherein the support comprises at least 90 wt. % alumina, based on a total weight of the support, wherein the catalyst comprises the copper salt in an amount of from 15 to 18 wt. %, based on a total weight of the solid catalyst, and wherein the solid catalyst comprises no activated carbon.
 14. The method of claim 13, wherein the support is α-Al₂O₃.
 15. A method of reducing an initial H₂S content in a gas mixture, the method comprising: passing the gas mixture, comprising H₂S and a hydrocarbon; through an aqueous suspension of a solid catalyst comprising a copper salt impregnated on a support, the aqueous suspension having a solid-liquid ratio, measured as solid catalyst mass per mass of liquid, is in a range of from 0.01 to 1.5; and separating a second gas from the gas mixture passed through the aqueous suspension comprising at least 90 wt. % of liquid water, the second gas having an at least 95% reduced H₂S content relative to the gas mixture, wherein the solid catalyst comprises at least 95 wt. % copper, based upon a total active metal content in the solid catalyst, wherein at least 90 mol % of the copper in the copper salt is copper (II), wherein the copper salt is selected from the group consisting of Cu(NO₃)₂, CuCl₂, Cu(CO₃), Cu(HCO₃)₂, Cu(SO₄), and mixtures thereof, wherein the solid catalyst comprises less than 1 wt. % CuO and less than 1 wt. % Fe, based upon the total active metal content in the solid catalyst, wherein the support comprises at least 90 wt. % alums, based on a total weight of the support; wherein the catalyst comprises the copper salt in an amount of from 15 to 18 wt. %, based on a total weight of the solid catalyst, and wherein the solid catalyst comprises no activated carbon.
 16. The method of claim 15, wherein the support is α-Al₂O₃. 